Declining production from conventional hydrocarbon reservoirs, coupled with increasing demand for energy worldwide, has resulted in a major shift towards the commercialisation of unconventional hydrocarbon resources (those that require greater than industry-standard levels of technology or investment). This paradigm shift has been facilitated by a combination of higher gas prices and key technological breakthroughs over the last 20 years or so. Unconventional gas is at the forefront relative to unconventional oil due to its geographical abundance and the fact that its use as a fuel is more environmentally friendly than the combustion of oil or coal. Indeed, gas is often thought of as being a “transition fuel” in advance of cleaner, renewable alternatives.
Conventional hydrocarbon reservoirs are those that can be produced at economic flow rates and that will produce economic volumes of hydrocarbons without the assistance of large stimulation treatments or special recovery processes. These are high to medium permeability reservoirs in which a vertical well can be drilled by a conventional drilling rig, a pay interval perforated and the well produced at commercial flow rates, recovering economic volumes of hydrocarbons with minimal assistance. An unconventional hydrocarbon reservoir is one that cannot be produced at economic flow rates or that does not produce economic volumes of hydrocarbons without the assistance of massive stimulation treatments or special recovery processes and technologies, such as steam injection. Typical unconventional reservoirs are tight sandstone gas, shale gas, coal seam gas, hydrate gas and heavy oil.
Conventional drilling rigs that are used to create the borehole generally include a drilling mud circulation system, where a suitable drilling fluid (generally referred to as “drilling mud”) is circulated under high pressure down through a hollow drill string (a jointed metal pipe), to a point at or near the advancing face of the borehole, and then back up to surface via the annular space (often simply referred to as “the annulus”) formed between the drill pipe and the borehole wall. The drilling mud acts to cool the drill bit and remove the cuttings during drilling, and also acts to suspend the cuttings while drilling is paused. The drilling mud returned to surface in this manner includes the cuttings (which would subsequently be separated so the drilling mud can be re-used), but also any gas that enters the borehole from whatever geological features are passed through (including both known and unknown hydrocarbon reservoirs) during the drilling.
During a normal drilling operation, when the drilling mud reaches surface it passes through a large valve capable of sealing and isolating the borehole to stop formation (i.e. geological) fluids entering the borehole (with potentially hazardous expulsion at surface) when high pressure zones are encountered which exceed the confining hydrostatic pressure of the drilling mud in the borehole. This device is often referred to as a “blowout preventer”, or a “BOP”. At the top of the blowout preventer, the drilling mud enters a flow diversion device (often referred to as a “bell nipple”). From here, the drilling mud enters a flow line which transports it by gravity to a series of drilling mud storage tanks.
A bell nipple is a section of large diameter pipe, fitted to the top of the blowout preventer and open to atmosphere, to which is attached the flow line via a side outlet. Before reaching the drilling mud storage tanks, the drilling mud is exposed to whatever separation, collection and/or treatment equipment is required, such as screens and sieves to remove the cuttings, filters to remove silt and sand, and purifiers to extract reusable drilling mud that can then be recirculated (as mentioned above) down through the hollow drill string to a point at or near the advancing face of the borehole. Additionally, any gas contained in the drilling mud is allowed to vent to atmosphere via the bell nipple, and at various other locations further downstream, culminating at the drilling mud storage tanks. Drilling mud in this system can be referred to as “recirculated drilling mud”.
It will be appreciated that the main function of the blowout preventer is to be able to seal the borehole (or more particularly the annulus) before or after drilling, or when drilling is paused, to prevent liquids and gases from unintentionally escaping. However, during drilling the blowout preventer will remain open to allow the passage therethrough of the drilling mud in order to permit the drilling mud circulation system to operate normally.
There will normally be a zone of interest that is targeted by the drilling, with the aim of directing the drilling such that the borehole passes through that zone of interest.
One of the major challenges in conducting an economic assessment of most unconventional gas play resources is the high uncertainty associated with current techniques for measuring the in-situ Total Gas content of a zone of interest in a targeted geological reservoir. This is particularly the case for deeper reservoirs.
The gas content of unconventional reservoirs is generally regarded as being divided into three components:Total Gas=Free Gas+Adsorbed Gas+Solution Gas
Free Gas exists in pore space, natural fractures or cleats (in the case of coal); Adsorbed Gas exists in a semi-liquid, monolayered state, bound typically but not exclusively to organic carbon by weak Van der Waals intermolecular forces; and Solution Gas is dissolved in formation water, liquid hydrocarbon, or a combination of both. Solution Gas can be quite significant in some oil reservoirs. With regard to typical unconventional gas play resources, in tight sandstone it is the Free Gas that forms the bulk of the Total Gas content, whereas in shale the Free Gas and Adsorbed Gas components are generally comparable. In contrast, in coal it is the Adsorbed Gas that predominates, although there may be a significant Free Gas contribution.
The techniques most often adopted in order to estimate the in-situ Total Gas content of an unconventional gas reservoir (or one of the above components of Total Gas) are as follows:                1. Mudlogs—this technique provides a qualitative indication of Total Gas, impacted by numerous drilling parameters.        2. Desorption (i.e. degassing) of conventional core or cuttings obtained during a drilling operation—this technique attempts to quantify Total Gas.        3. Porosity/water saturation from conventional core or cuttings obtained during a drilling operation—this technique attempts to quantify the Free Gas in pore spaces.        4. Porosity/water saturation from conventional electric logs—this technique also attempts to quantify the Free Gas in pore spaces.        5. “Unconventional” electric logs—use of these provides an ability to quantify both the Free Gas in pore spaces and the Adsorbed Gas in terms of Total Organic Carbon (TOC), thereby providing a measure of the Total Gas.        6. Adsorption isotherms performed on conventional core or cuttings obtained during a drilling operation—this technique quantifies the Adsorbed Gas.        7. Pressure core techniques—these are generally able to quantify the Total Gas in a reservoir, relying on the trapping of gas in a sealed container at bottom-hole pressures in a well and the subsequent raising of the container (typically at thousands of psi gas pressure) to surface.        
Options 1 to 5 above tend to have a high degree of uncertainty for a variety of different reasons. Option 6, although generally accurate, tends to provide only one component of the Total Gas content, which for many types of unconventional gas reservoirs is not particularly useful. Finally, while option 7 is the most accurate for providing an estimation of the Total Gas content of an unconventional gas reservoir, such techniques are currently problematic due to a) availability, b) logistics, c) cost, d) complexity, e) safety and f) mechanical success rate.
Turning to a more specific discussion of the more common types of unconventional gas reservoirs and their normal gas measurement options, for coal seam gas reservoirs Option 2 (relying on the canister desorption of conventional core) has so far been the most widely used approach for measuring Total Gas in these relatively shallow reservoirs (less than approximately 3,000 feet). Unfortunately though, despite efforts to bring the core to surface as quickly as possible, the core retrieval time negatively impacts on the amount of gas captured in the desorption canisters at surface. This typically results in an underestimated in-situ Total Gas content. Indeed, during retrieval, the surrounding drilling mud hydrostatic confining pressure decreases and gas thus escapes from the core.
To compensate, a “Lost Gas” correction must be applied, which is normally done by extrapolating the early-time degassing trend, measured as close as possible to reservoir temperature in desorption canisters at surface, back to “time zero”. The latter is defined as the point in time at which the pressure differential across the drilling mud-core interface changes from overbalance to underbalance and gas starts to escape. The deeper the cored zone, the longer the retrieval time, and hence the larger is the proportion and uncertainty of the Lost Gas component. The high uncertainty associated with Lost Gas determination is a major deficiency in this approach.
For shale gas reservoirs, the Total Gas has typically previously been determined by combining options 3, 4 or 5 above with option 6, which has the effect of adding Free Gas and Adsorbed Gas to provide a result for the Total Gas. For these reservoirs, desorption is considered unreliable, again due to the large Lost Gas component associated with retrieving core from the greater depths at which viable shale gas reservoirs are generally found. A problem with the shale gas approach is that porosity and, particularly, water saturation measurements, on which the Free Gas component is normally calculated, are subject to significant uncertainty.
The present applicant has a deep unconventional gas asset in the Cooper Basin (including tight sandstone, shale and coal), ranging from approximately 8,000 to 12,000+ feet, and for the reasons outlined above is experiencing difficulties accurately quantifying Total Gas content. To evaluate this resource using known techniques used by the coal seam gas industry, conventional core can be acquired (both drill pipe and wireline retrieved) and standard core desorption can be performed in an attempt to estimate the Total Gas content. Unfortunately though, the retrieval time from these depths (plus the handling time at surface) is generally in the order of 2 to 10 hours.
This strongly contrasts with what is considered “reasonable” in the shallow coal seam gas industry (which is a Lost Gas time of less than 1 hour and typically of only 15 minutes). This highlights the problem with evaluating deep zones, as is typical with many unconventional gas reservoirs. Indeed, it becomes necessary to apply a very large, highly uncertain and probably invalid, Lost Gas correction, potentially in excess of the actual amount of gas recovered.
While Option 7 may technically provide a reasonable alternative, the equipment required to undertake pressure core measurement techniques is expensive and difficult to source, and tends to introduce unnecessary (or at least undesirable) mechanical complexities.
It is an aim of the present invention to provide a more reliable and more accurate method and apparatus for the measurement of the Total Gas content of unconventional reservoir rock (be it sedimentary, igneous or metamorphic rock), and in particular for the measurement of the in-situ Total Gas content of an unconventional gas reservoir, when compared to Options 1 to 6 above, and a more convenient and cost-effective method and apparatus when compared to Option 7. In this respect, it will be appreciated that while the motivation for developing the method and apparatus of the present invention might lie in the realm of unconventional gas reservoirs, the method and apparatus will nonetheless still be usable in relation to the measurement of the in-situ Total Gas content of unconventional oil reservoirs.
Reference to any prior art in this specification is not, and should not be taken as, an acknowledgment or any form of suggestion that this prior art forms part of the common general knowledge in any country.